Petroleum Geoscience - Volume 5, Issue 1, 1999

In the 1970s and 1980s exploration performed within the Polish part of the Permian Basin, particularly in the Gorzow region, found the Main Dolomite (the Upper Permian-Zechstein) formation to be very prospective, as proved by the discovery of many oil and gas fields. In the early 1990s exploration based on 2D seismic intensified and resulted in the definition of three separate structures: Barnowko, Mostno and Buszewo. The exploration wells located on these structures found the first two to be gas-bearing and the third to be oil-filled. Subsequent interpretation of the 3D seismic showed that, in reality, the three discoveries are a single field. This conclusion was based on the analysis of geometry and distribution of the reservoir parameters. It has been proved by the results of eleven consecutive wells (since writing this paper a further 6 wells have been drilled which confirm the interpretation). All of the above shows this field to be the largest oil field of the Polish part of the Permian Basin, as well as the largest in Poland.

This paper describes how 87 Sr/ 86 Sr ratios in formation waters are used to evaluate compartmentalization of hydrocarbon reservoirs. Strontium Isotope Residual Salt Analysis (SrRSA) of core samples provides a means of measuring 87 Sr/ 86 Sr ratios in formation water from hydrocarbon columns and aquifers. Smooth SrRSA profiles suggest progressive, uninterrupted, filling and the absence of sealed barriers, while a step change in a profile normally suggests a barrier sealed up-dip from the well penetration. Inferences about lateral connectivity are made by comparing SrRSA profiles from neighbouring wells at TVD. Profiles that are superimposed when plotted at TVD suggest the well sections share a common filling history and lie in the same flow unit. Neighbouring SrRSA profiles that are not superimposed normally suggest segmented compartmentalization of the reservoir. Post-fill structural tilting of reservoirs and hydrodynamism synchronous with filling are processes which complicate data interpretation. Drilling mud contamination of core water is the most serious technical limitation of the SrRSA technique.

The dependency of waterflood remaining oil saturation (S or ) on initial water saturation (S wi ), wettability and flow rate has been studied in the laboratory at core scale. For both water-wet and mixed-wet cores, S or was found to be inversely proportional to S wi . For mixed-wet cores, S or was also found to be inversely proportional to the number of pore volumes injected. In contrast, water-wet cores showed a dependency between S or and flow rate, indicating that pore structure plays an important role. The oil saturation development in several waterflooded intervals in the Gullfaks Field has been monitored, mainly by saturation logs, over several years. Oil saturation was found to decrease inversely with time after water breakthrough. Also, an oil saturation distribution with depth, which seems to depend on the balance between capillary and gravitational forces, was found.

Contact angle has a major influence on the distribution of multi-phase fluids within petroleum reservoir rocks. However, there is little information on the variation of gas-oil-rock contact angle with pertinent parameters in the literature. In this study, it has been observed that the contact angle is almost constant at high gas-oil interfacial tension (IFT) above a threshold value and declines at a variable rate, depending on the volatility of the mixture, approaching zero at the critical point. The generated data were used to develop a generalized correlation between the contact angle and IFT and other measurable parameters of the system.

The Cenomanian-Turonian transgression has been studied in a 220 m cored section using common source rock data, elemental data and conventional biomarker parameters. Differences in the type of organic matter found in these regressive and transgressive offshore marine sediments have been documented and assessed within a sequence stratigraphic framework. The interval of maximum flooding of the Cretaceous seaway shoreline is delineated by discontinuities in the total organic carbon content and Hydrogen Index. The overall transgressive event is also accompanied by (a) an increase in the concentrations of elements such as thorium, vanadium, potassium, barium, sodium...etc., (b) changes in the relative concentrations and the characteristics of the biomarker parameters and (c) changes in the characteristic features of the kerogen. All of these data are consistent with a simultaneous decrease in terrigenous organic matter and increase in marine algal input.

Fault zone properties are incorporated in production flow simulators using transmissibility multipliers. These are a function of properties of the fault zone and of the grid-blocks to which they are assigned. Consideration of the geological factors influencing the content of fault zones allows construction of high resolution, geologically driven, fault transmissibility models. Median values of fault permeability and thickness are predicted empirically from petrophysical and geometrical details of the reservoir model. A simple analytical up-scaling scheme is used to incorporate the influence of likely small-scale fault zone heterogeneity. Fine-scale numerical modelling indicates that variability in fault zone permeability and thickness should not be considered separately, and that the most diagnostic measure of flow through a heterogeneous fault is the arithmetic average of the permeability to thickness ratio. The flow segregation through heterogeneous faults predicted analytically is closely, but not precisely, matched by numerical results. Identical faults have different equivalent permeabilities which depend, in part, on characteristics of the permeability field in which they are contained.

We carried out experiments to study the effect of wettability heterogeneities on: (1) displacement mechanisms, (2) sweep efficiency and (3) trapped oil quantities and fluid distribution in three-phase gas injection and developed a theoretical simulator. Secondary gas injection experiments was conducted in transparent glass micromodels of heterogeneous wettability. Oil-wet patches in a water-wet matrix were obtained by selective silane grafting on the glass surface. Different heterogeneity patterns were considered for the same oil-wet over water-wet surface ratio. Displacement sequences were video-recorded and fluid saturations determined by image analysis. A theoretical model of three-phase flow in a porous structure was developed. In this model the porous medium is simulated as a network of interconnected pores. The model permits an imposition of heterogeneous wettability by assigning different water-oil contact angles according to the desired wettability pattern. The calculation of flow within the network takes into account the flow of oil through wetting and spreading films and the displacement mechanisms observed in the transparent micromodels. Comparison between experimental results and simulations shows that the size and distribution of wettability heterogeneities strongly affects microscopic and macroscopic behaviour during gas injection.

This paper investigates theoretically the possibility of describing foam flow through porous media based upon the usual equations for two-phase flow of immiscible fluids through porous media. It found a class of solutions which can describe the main features of foam flow during gas mobility reduction (gas-blocking regime). An expression for the "gas mobility reduction factor" has been derived from the current consideration. The analysis of this expression shows that this factor is equal to the ratio (liquid mobility without foam)/(gas mobility without foam) at liquid saturation very close to the irreducible one. A method for calculating the gas mobility reduction factor is proposed.

The Villeperdue field produces oil from a thin and heterogeneous carbonate reservoir of middle Jurassic age. Despite the presence of 150 wells, the production of this field (about 9000 bbl/day) is decreasing continuously and forecasting the productivity of new wells remains hazardous. In a joint effort by four operators, a contractor and a research institute, advanced seismic methods including 3D, 2D-3c (3 components), 2D-HR (High Resolution) and 3c-VSP (borehole seismic) were combined to improve reservoir characterization and define methods for revitalizing exploration in the Paris Basin. The combination of continuous spatial sampling, such as that obtained in 3D, and a Vibroseis emission adapted to the high-frequency attenuation, such as that used in 2D-HR, supplied useful information about the reservoir heterogeneities which cannot be provided by correlation of the well data. In this way thickness, lateral porosity variations and small faults (throw <10 m) were successfully detected, making it easier to select the locations of new production wells.

An integrated optical (palynofacies) and bulk organic geochemical study has been undertaken in order to determine the controls on the organic facies of paralic Middle Jurassic Hebridean sediments. The total organic carbon (TOC) values are generally between 0.5 and 2.5%, but reach up to 3-4% in dark-coloured non-bioturbated shales within the Bearreraig Sandstone Formation and Lealt Shales Formation, and 6-8% in the Staffin Bay Formation. Hydrogen indices (HI) are mostly below 300, increasing to 400-500 in the aforementioned organic-rich intervals, and reaching 650-800 in the Kilmaluag Formation. The best overall source potential probably occurs in the brackish Lealt Shales Formation. Correlations between HI, TOC and the content of the freshwater alga Botryococcus (< or =9% of the kerogen), suggest that freshwater run-off may have led to stratification of the Middle Jurassic lagoons, and thus dysoxic-anoxic bottomwaters and better quantitative and qualitative preservation of the plankton-derived amorphous organic matter.

CaCO 3 scaling at 120 degrees C and formation water flow along well tubing during production, is modelled using tube blocking experiments utilizing Na-K-Ca-Cl-HCO 3 -H 2 O brines. All tests produced scale assemblages dominated by aragonite, vaterite (< or =45%) and some calcite. Vaterite is a rare form of CaCO 3 so its occurrence is particularly significant. Vaterite precipitation was initiated by rapid CaCO 3 supersaturation, driven by lower CaCO 3 solubility at 120 degrees C, combined with high relative concentrations of HCO (super -) 3 in the brine (HCO (super -) 3 /Ca = 12). Few accounts of oil field scaling focus on carbonate mineralogy. The formation of mixed-carbonates in this study emphasizes that more attention should be paid to mineralogical characterization of carbonate scale in relation to production conditions, formation water chemistry and inhibitor selection. This could lead to improvements in both scale prediction and inhibitor efficiency.